Ditto Urges Members To Share Supply Chain Challenges, Details APPA Efforts To Address Issue
June 13, 2022
by Paul Ciampoli
APPA News Director
June 13, 2022
Joy Ditto, President and CEO of the American Public Power Association (APPA), on June 13 urged member utilities to share their supply chain challenges with APPA so that the trade group can relay details on these challenges to federal partners and discuss how critical burdens on the sector can be alleviated.
“Thanks to your responses to our surveys and other outreach, we already know that transformers are extremely constrained,” she said in her remarks at APPA’s National Conference in Nashville, Tenn.
APPA is proactively taking steps to address supply chain challenges.
“We have done several things from our end to help,” Ditto said, noting that APPA recently asked the Department of Energy for a temporary waiver from the 2016 transformer efficiency standard to help spur faster manufacturing processes.
In addition, APPA rolled out an additional feature to APPA’s eReliability Tracker that is available to all public power utilities and allows for voluntary equipment sharing by matching systems with the same distribution voltages.
“We are relaying to the federal government what the challenges are and working with manufacturers to better understand and” alleviate constraints, Ditto said.
“This conversation will become more formalized with a tiger team being formed between the electric sector and the Department of Energy, with transformer manufacturers and other manufacturers included as well.”
This tiger team is under the auspices of the Electricity Subsector Coordinating Council, led by the various electricity trades and select CEOs from the industry, including several from public power.
“We have also sent letters to the congressional energy committees on the transformer constraint,” Ditto said.
Cyber Security
Meanwhile, APPA and the electric sector are keeping cybersecurity front and center in 2022, “as we have been for many years.”
She noted that public power utilities have the opportunity to engage in information sharing, cyber mutual aid and more.
“The Infrastructure Act includes $2 billion for cybersecurity and there is $250 million of that $2 billion earmarked for technical assistance and support specifically for municipal and rural utilities.”
Tax-Based Incentives
APPA also continues to fight for tax-based incentives for renewable energy, including wind and solar, to be expanded to allow for nonprofit electric utilities to receive comparable financial incentives in directly owning these projects.
There appears to be bipartisan support for extending such energy credits, including a refundable direct pay credit, she said.
Natural Gas
She pointed out that public power’s transition to cleaner forms of energy is challenged by the interdependencies inherent to the industry. “Unfortunately, sometimes we can’t work on challenges that stem from these dependencies until people see the true need.”
An example of this was last year’s Winter Storm Uri.
“APPA had outlined some issues with increased reliance on natural gas for electricity production back in 2010, but it wasn’t until the storm triggered some of the worst-case scenarios that people started to focus on some of the policy solutions we had previously put forth,” Ditto said.
“We’ve made some progress in this area, but we still need to work toward getting assurances in the gas market via policy-based solutions. Rising natural gas prices over the last several months are only exacerbated by infrastructure siting barriers and contradictory policies that delay permitting.”
Light Up Navajo
Public power utilities continue to work on connecting families to the grid through the Light Up Navajo initiative in partnership with the Navajo Tribal Utility Authority.
“Having visited the Navajo Nation for the kick-off of this year’s Light Up Navajo III event in April, I felt the gratitude for what our shared efforts could produce — how much of a difference electricity means to people’s lives shines through in the testimonials from the volunteer crews and the families that newly received power to their homes,” she said.
EIA Expects Natural Gas Spot Prices To Remain High Through Rest Of 2022
June 12, 2022
by Paul Ciampoli
APPA News Director
June 12, 2022
The Energy Information Administration (EIA) is forecasting that U.S. natural gas spot prices will increase again in June and then remain high through the rest of 2022.
Natural gas spot prices at the U.S. Henry Hub benchmark in Louisiana averaged $8.14 per million British thermal units (MMBtu) in May 2022, and EIA expects the Henry Hub price to average $8.71/MMBtu this summer (June through August).
It expects U.S. natural gas prices to remain relatively high in 2022 because of lower-than-average natural gas inventories resulting from factors affecting both supply and demand.
Consumption of natural gas in the U.S. electric power sector has remained high despite high natural gas prices.
“We expect that consumption of natural gas in the U.S. electric power sector will average 0.9 billion cubic feet per day (Bcf/d) more in 2022 than in 2021, even though we expect the Henry Hub price to be $3.49/MMBtu higher,” EIA said.
In the U.S. electric power sector, power plants have tended to consume more coal as natural gas prices increase. However, this fuel substitution has been relatively limited in recent months because of supply constraints in the coal market and historically low coal stockpiles, the agency noted.
In addition, EIA expects that U.S. exports of liquefied natural gas (LNG) will remain high during this summer, partly as a result of Russia’s full-scale invasion of Ukraine. So far this year, 75% of total U.S. LNG cargos have gone to Europe, compared with 34% in 2021. High international natural gas prices may also lead to more U.S. LNG exports.
EIA expects U.S. production of dry natural gas to increase in 2022, but not as much as demand. “We expect dry natural gas production will average 96.5 Bcf/d in 2022, which is 3.2% (or 3.0 Bcf/d) higher than the 2021 average.”
Because demand for natural gas has outpaced production, natural gas inventories have remained low. Natural gas inventories started the 2022 summer injection season (April through October) 17% below the five-year (2017–21) average. “We expect that natural gas storage levels will be 9% below the five-year average at the end of October, the beginning of this coming heating season.”
EIA forecasts that natural gas prices will fall in early 2023 because of more domestic natural gas production, less LNG export and domestic natural gas demand growth, and more natural gas placed in storage.
Rising Natural Gas Prices Fuel Concerns Of Higher Electric Prices Through Summer
June 8, 2022
by Peter Maloney
APPA News
June 8, 2022
Soaring natural gas prices ahead of the summer cooling season are fueling growing concerns in the electric power industry.
“Natural gas power generation sets the marginal price of wholesale power across the country, which means that as natural gas prices increase, so will the price of electricity,” Paul Cicio, president and CEO of Industrial Energy Consumers of America, said via email. Wholesale power prices have already increased over 200 percent regionally, he noted.
The concern is great enough that the Federal Energy Regulatory Commission (FERC) last month in its 2022 summer assessment warned that expectations of a hotter than average summer could increase electric demand, creating demand for natural gas that is expected to outpace supply growth. Futures prices at major electricity trading hubs are already between 77 percent and 233 percent higher than they were last year, FERC said.
Those factors are already evident in the gas market. The Henry Hub natural gas spot price hit $9.30 per million British thermal units (MMBtu) on May 24, about three times higher than the price a year ago. The cost of purchasing gas in advance is also on the rise. The June 2022 NYMEX contract increased 60.3 cents, from $8.368/MMBtu on May 18 to $8.971/MMBtu on May 24, according to the Energy Information Administration reported (EIA).
For over a decade, prices and emission levels lower than other fossil fuels has made natural gas the leading power generation fuel. Natural gas, at 38 percent, was the leading power generation fuel in 2021, followed by coal with about 22% of the generation market, according to EIA data.
When natural gas prices were low because of a flood of gas from fracking, utilities and their customers benefited from low electricity prices. With gas prices on the rise, customers are beginning to feel the pain. EIA data show across the board increases in electricity prices in all sectors and all regions of the country.
In the PJM Interconnection, the real-time load-weighted average locational marginal price increased 75.5 percent in the first three months of the year compared with the first three months of 2021, to $54.13 per megawatt hour (MWh) from $30.84/MWh, the highest first quarter price since the polar vortex of 2014, according to the State of the Market Report from Monitoring Analytics, the independent monitor for the PJM. Forty-nine percent of the increase was a direct result of higher fuel and emission costs, particularly higher natural gas prices, the report said, noting that generation from coal-fired plants decreased 3.1 percent while generation from natural gas-fired plants increased 6.9 percent from first-quarter 2021 to first-quarter 2022.
The last quarter also marked the highest natural gas and locational marginal prices since 2014 for ISO New England. Total estimated electricity wholesale market costs this winter were $4.28 billion, up 85 percent from $2.32 billion in the winter of 2021, while natural gas prices averaged $14.41/MMBtu this winter, up 147 percent compared with $5.82/MMBtu last winter, according to the ISO’s Winter 2022 Quarterly Markets Report.
Florida, which of all the states is the most dependent on natural gas for power generation, provides another example of how vulnerable utilities can be to rising prices.
“We are on the bleeding edge of price increases,” Jacob Williams, general manager and CEO of Florida Municipal Power Agency (FMPA), said.
“Florida is unique,” said Williams. In addition to its dependence on natural gas, there is zero wind power and only two percent solar power. Solar power is slated to go up to 10 percent in the Sunshine State, but it is not meaningful in terms of reliable capacity because frequent summer rain storms obscure the sun, Williams said.
“In the past, coal provided a natural ceiling on gas prices,” Williams said. Operators could switch between gas plants and coal plants depending on price, but coal prices have also risen dramatically.
Central Appalachian coal has more than doubled over the past year. In addition, coal producers are having trouble meeting demand and stockpiles at power plants have fallen to historically low levels.
Florida also has one of the highest percentages of older residents, many of whom are on fixed incomes. About 30 percent of Floridians spend about 10 percent of their after-tax income on their electric bill, said Williams.
FMPA, which has 31 member cities throughout the state, serves about 12 percent of the state’s 21 million people. About 80 percent of its generation fleet is powered by natural gas, and gas prices have tripled in the last year. That has pushed wholesale power prices up to $110 per MWh from $70/MWh, a 30 percent year-over-year increase, Williams said. “It has been a more significant cost increase than anyone had planned on.”
“While not predicting it, I would not be surprised if gas prices were $12/MMBtu,” Williams said. “There does not seem to be a price ceiling until $20/MMBtu or more.”
Upward Pressures on Natural Gas
Natural gas prices began their upward trend early in 2021 when a winter storm in Texas and Oklahoma caused a spike in prices in February. Prices continued to rise through October as economic recovery contributed to growth in gas demand, which outpaced supply, even though gas production in 2021 reached an annual high of 2.97 billion cubic feet per day (Bcf/d), surpassing the previous high of 2.95 Bcf/d set in 2019, according to the EIA.
Cold weather this winter that extended into late spring added to upward pressure on gas prices, which led to below normal injections of gas into storage for the coming heating season as gas already in storage was drawn down to meet winter heating demand. “Injections are just now starting to reach normal,” David Givens, head of natural gas and power services for North America at Argus Media, said.
But that is just one element in a larger picture. Liquefied natural gas (LNG) exports also rose to record levels in 2021. South Korea and China were the top destinations for U.S. exports, but there was also strong demand from Europe, driven by the relatively low price of U.S. natural gas. “Europe will take all the gas we can make,” Givens said.
With European sanctions against Russian energy imports to protest Russia’s invasion of Ukraine, demand for exports is likely to go even higher.
U.S. export capability does have limits, which could act as a temporary limit on LNG-driven price increases, but new LNG facilities are already in the works. A new facility just went online in Louisiana, and “there are many LNG terminals in the works for 2024 and 2025,” Givens said.
Gas production increased last year, but demand has increased even more, Cicio said. If not for LNG exports, “U.S. natural gas prices would be about $3.50/MMBtu.” Because production is not rising fast enough, Cicio estimated that gas prices could rise to over $10/MMBtu, at which point gas would no longer be economic to export, he said.
Givens does not see a ceiling on export driven prices. “Europe and Asia have bought LNG at $30 in the past,” he said.
Even if gas production increases, other constraints are putting upward pressure on prices. Problems building new pipelines put limits on getting gas out of the field and into the market. “In some respects, that is a regional problem,” Cicio said.
There are abundant supplies of shale gas in the Appalachian Basin, but “the entire East Coast from South Carolina to New York is short pipeline capacity,” Cicio said.
Proposed gas pipelines into New York and in New England have consistently met challenges or been struck down. In February, a permit for the Mountain Valley Pipeline project, designed to move gas from northern West Virginia to coastal Virginia, was vacated by a federal court. In July 2020, the Atlantic Coast Pipeline, which would have moved gas from West Virginia to Virginia and North Carolina, was cancelled after years of litigation and cost increases.
Shortly after he took office, President Joe Biden suspended new oil and gas leases on federal lands, most of which are in the West. The moratorium was blocked by a federal judge in June. In April, faced with rising inflation and energy prices, Biden ended the moratorium.
“The refusal to grant new leases is not a major factor in rising gas prices,” said Givens. Instead, he emphasizes near- and medium-term fundamentals such as rising demand for electric power and LNG.
Looking for Relief
The current shape of the forward curve could hold the prospect of some relief for utilities over the next couple of years. For the balance of 2022, the forward curve at Henry Hub is $8.12/MMBtu. For 2023, it is $5.72/MMBtu, and for 2024, it is $4.56/MMBtu.
The big question is whether producers will ramp up production. With the forward curve declining over time – backwardation in industry terms – “it is speculative for them to commit capital for drilling,” Givens said.
After a roughly 10-year tidal wave of shale gas that depressed commodity and stock prices, “producers are finally in the driver’s seat,” Givens said. They “have free cash flow, and they are turning it into dividends and giving it to shareholders. That is their primary goal now.”
On a practical basis, that means during this transition, utilities should have a scenario that plans for gas to be $5 to $10 for the medium term, Givens said.
Faced with the politically untenable prospect of passing on large price increases to customers, utilities are looking for options. In the past, some utilities had been wary of locking in a gas price by hedging either because they became accustomed to low prices or they were burned by locking in prices only to see them drop even further.
Williams says FMPA has already done all “the blocking and tackling” it can do to get prices down. It has taken $30 million a year out of its budget by pre-paying for natural gas to reduce prices, selling excess power from an under used power plant, having its plants operate at high levels of availability, and refinancing bonds.
Now, FMPA and its members are looking at hedging their gas purchases to lock in prices before they rise even further. Some members are acquiring gas for next year, said Williams.
If they can lock in a price of $85/MWh, it isn’t $70/MWh, but “it is a lot less than $110/MWh,” he said.
Williams also favors lobbying Congress and the president to invoke the War Powers Act to expedite the approval of new leases that could potentially increase gas production and ease upward price pressures.
Minnesota public power utility New Ulm Public Utilities has already hedged its supplies for 2022. The hedge locked in a price of $2.77/MMBtu for about a third or half of the utility’s summer natural gas load, “not something we typically do,” Kris Manderfeld, director of the Minnesota public power utility, said.
That hedge only covers the utility’s gas business. On the electric power side, New Ulm has about nine years left in a 20-year, 180-megawatt (MW) contract with Heartland Consumers Power District. The contract covers about 50 percent of New Ulm’s electric load. The utility meets the rest of electric demand with purchases from the Midcontinent ISO. Those prices have been higher than last year, said Manderfeld.
Typically, New Ulm wants its baseload needs covered by contract and uses MISO purchases for load following, Manderfeld said. Otherwise, the utility is urging customers to conserve energy.
“There does not appear to be a cap on gas prices,” Manderfeld said. “People are still paying the price, even though there is nothing out of the normal. Supply is where it needs to be. Our consultants say the only thing driving up prices are fear and uncertainty.”
“We will keep trying to do what we can for our customer, to keep the prices competitive,” Manderfeld said.
APPA Analysis Examines Regulated, Deregulated State Power Price Trends
June 6, 2022
by Paul Ciampoli
APPA News Director
June 6, 2022
Increases in retail electric prices from 1997 to 2021 were about half a cent more in states with deregulated electric markets than in regulated states, though regulated states had a slightly higher percentage increase in prices, according to an American Public Power Association (APPA) analysis of data from the U.S. Department of Energy’s Energy Information Administration.
APPA’s analysis also found that rates increased significantly in all states from 2020 to 2021, largely attributable to a rise in natural gas prices. Average total rates increased by six-tenths of a cent, or 5.7%.
Also, average rates in regulated states increased by 5.3% (from 9.5 cents to 10 cents), compared to a 6.7% increase in deregulated states (from 12 cents to 12.8 cents).
Since 2012, residential rates in deregulated states have increased by 2.5 cents, compared to a 1.4 cent increase in regulated states.
The report reviews data on electric rates in 16 states plus the District of Columbia — those with “retail choice” in place — compared to states that have traditional rate regulation.
The data show that after 24 years of deregulation, the original promise of reduced prices has not materialized, APPA said.
The full report is available here.
APPA’s Delia Patterson Joins Advisory Board Of E Source
June 1, 2022
by Paul Ciampoli
APPA News Director
June 1, 2022
Delia Patterson, Senior Vice President of Advocacy and Communications and General Counsel at the American Public Power Association (APPA), has joined the advisory board of E Source, the company announced on June 1.
“I’m thrilled to join the E Source advisory board and to contribute to furthering E Source’s mission,” said Patterson. “I look forward to connecting with my fellow advisory board members, the E Source team, and E Source clients to make significant progress on critical industry issues.”
“We’re extremely fortunate to have Delia join the E Source family,” said Ted Schultz, CEO of E Source. “Her insights and experience will help us deliver on E Source’s mission to build a sustainable future in partnership with utilities. She has spent her career helping utilities do the hard work they need to do and advocating for the interests of public power.”
E Source is a research, consulting and data science firm for the utility sector.
Patterson was recently elected president of the board of directors of the Energy Bar Association.
Patterson is also a member of the Department of Energy’s Electricity Advisory Committee, a member of the Lawrence Berkeley National Laboratory Future Electric Utility Regulation Advisory Group, and an associate member of the Commodity Futures Trading Commission Energy and Environmental Markets Advisory Committee.
She is also on the board of the Women’s Energy Resource Council and is the member of APPA’s executive leadership team who leads energy policy formulation and advocacy before federal agencies, federal courts, and various energy policy forums.
FERC Votes To Permanently End Use Of MOPR In New England After Two-Year Transition
June 1, 2022
by Paul Ciampoli
APPA News Director
June 1, 2022
The Federal Energy Regulatory Commission (FERC) on May 27 voted to approve a proposal submitted by ISO New England (ISO-NE) under which the grid operator will eliminate a minimum offer price rule (MOPR) in its forward capacity market (FCM) and replace it with a reformed buyer-side market power mitigation construct.
ISO-NE Proposal And Background
In March, ISO-NE and the New England Power Pool Participants Committee (NEPOOL) jointly submitted proposed revisions to the ISO-NE Transmission, Markets and Services Tariff to modify the current MOPR in the FCM.
ISO-NE proposed to permit a specified quantity of “sponsored policy resources” to enter the market without being subject to buyer-side market power mitigation review during the next two forward capacity auctions (FCA) 17 and 18, and thereafter, beginning with FCA 19, eliminate the current MOPR and replace it with a reformed buyer-side market power mitigation construct.
As part of its FCM, ISO-NE holds an annual FCA in which capacity suppliers compete to provide capacity to the New England region for the relevant delivery year, three years in the future. Suppliers of capacity that receive a capacity supply obligation in an FCA commit to, and receive payment for, providing capacity for that one-year period associated with that FCA.
Currently, ISO-NE’s buyer-side market power mitigation rules utilize a MOPR that requires new capacity resources to offer their capacity at prices that are at or above a price floor set for each type of resource. By imposing such a minimum offer price, the MOPR is intended to “mitigate” uncompetitively low bids, including resources that benefit from certain subsidies.
In its order, FERC notes that over the past decade, New England states have sought to reduce greenhouse gas emissions and meet climate goals through various mechanisms outside of the ISO-NE markets.
Those efforts have included legislation that allowed state-regulated utilities to enter into long-term contracts with certain defined resource types.
However, the MOPR does not allow resources receiving out-of-market revenues to account for that support in their offer prices, unless the support is widely available to other market participants.
As noted by ISO-NE in its filing, new resources supported through state legislation carry an elevated risk that their subsidized offers will be mitigated, making it more likely that they will fail to clear in the FCA.
ISO-NE acknowledges that, because capacity obligations generally must be met through resources that have cleared the FCA, exclusion of state-sponsored resources from the FCM forces consumers to effectively pay for capacity twice — once to meet the resource adequacy objectives of the FCM and a second time to meet the policy objectives of the states.
ISO-NE said that its MOPR reforms are necessary to facilitate entry into the FCM of substantial amounts of capacity from state-sponsored resources over the next several decades, avoiding the potential for an inefficient overbuild of the region’s capacity.
ISO-NE explained that New England states have undertaken significant clean energy and decarbonization initiatives over the last five years such that the existing market rules designed to accommodate the participation of state-sponsored resources within the FCM are unlikely to sufficiently address the potential for excess capacity procurement throughout the region.
Accordingly, ISO-NE proposed to implement certain MOPR reforms to replace the existing rules for state-sponsored resources, following a two-year transition period.
The grid operator proposed a transition mechanism for FCAs 17-18 to permit a defined quantity of state-sponsored resources unmitigated entry into the FCA in a measured fashion to protect reliability, investors, and consumers.
ISO-NE proposed a graduated replacement of the MOPR for two central reasons: (1) concerns about adverse impacts to reliability from inefficient retirements and from likely delays in the development of state-sponsored resources, and (2) the need to provide the region time to undertake market reforms to facilitate the reliable transition to the new resource mix.
Details On FERC Order
In its order, FERC determined that ISO-NE has shown that the proposed revisions “appropriately balance the need to mitigate the potential exercise of buyer-side market power against the harms of over-mitigation.”
FERC said that ISO-NE’s proposal “minimizes the potential for an inefficient overbuild of capacity while providing the necessary time for an orderly transition of the region’s resource mix that will protect reliability and provide market certainty.”
Implementing the MOPR reforms in conjunction with a limited transition mechanism “is a just and reasonable approach in this circumstance because it strikes a reasonable balance among” different considerations raised in the proceeding, including efforts to ensure resource adequacy, minimize potential adverse effects on reliability that could result from an immediate change to the market rules, promote market certainty, and limit the costs associated with over-mitigation.
FERC said that the purpose of the MOPR is to prevent the exercise of buyer-side market power and that it is not a tool designed to maintain reliability.
The MOPR “does not change the capacity accreditation of resources nor the total amount of capacity targeted in an auction. However, as it does directly change resources’ offers by imposing offer floors, it can impact the clearing price of an auction and alter which resources clear the auction,” FERC said.
“Therefore, ISO-NE has presented a reasonable case for why immediate removal of the MOPR in ISO-NE could exacerbate existing reliability challenges insofar as a one-time price shock to the capacity market could cause what it describes as the ‘disorderly’ or inefficient retirement of resources that could prove necessary to maintain reliability during extended cold conditions.”
FERC also found that the transition mechanism “promotes market stability and provides a measure of predictability to market participants by specifying the maximum amount of state-supported resources that may clear in FCAs 17 and 18 prior to implementation of the MOPR reforms in FCA 19.”
Commissioners Weigh In
In a concurrence to the order, FERC Chairman Richard Glick said he believes that the best outcome here would have been for ISO-NE to immediately implement its new MOPR, i.e., without the transition mechanism.
“Simply put, ISO-NE could have, and should have, done better. Nevertheless, ISO-NE submitted a different proposal—one that delays reform of the MOPR by two years—and we must evaluate the filing before [us],” he wrote.
When considered in that context, Glick believes that the proposed transition mechanism “is part of a just and reasonable package of reforms.”
In addition, “and critically, the New England States have explained that they do not oppose the transition mechanism,” he noted.
He said he recognizes that the changing resource mix is forcing the Commission, RTOs, and the states to take a new tack to ensuring reliability. “No one can dispute that. But the right way—and, in my view, the only just and reasonable way—to do so is by designing wholesale electricity markets to ensure reliability in light of that changing resource mix rather than trying to roll back the resource mix clock.”
He said it is not the Commission’s role to choose one resource type over another, or to second guess the wisdom of state resource decisionmaking. “Instead, we must ensure, in a resource-neutral manner, that wholesale electricity markets are procuring the services need[ed] to keep the lights on and the grid in balance.”
As a result of the order, ISO-NE “is free to do just that rather than engaging in a Sisyphean attempt to stymie state efforts through the capacity market. In this respect, I strongly encourage ISO-NE to move forward expeditiously in developing and filing a capacity accreditation proposal to ensure that the FCM is accurately valuing the capacity contribution of all resources. Done right, capacity accreditation can serve as a prime example of how Commission-jurisdictional markets can ensure reliability in a manner that compliments, rather than contradicts, states’ exercise of their sovereign authority—exactly the type of ‘cooperative federalism’ that I believe should typify the Commission’s interaction with the states and its regulation of wholesale markets more generally,” wrote Glick.
Commissioners Allison Clements and Willie Phillips offered a joint concurrence.
“We vote to accept ISO-NE’s tariff filing because it sets the region on course to eliminate the Minimum Offer Price Rule (MOPR), a likely unjust and unreasonable tariff mechanism that, if left uncorrected, could force customers in New England to pay millions or even billions to prop up capacity that they do not want or need,” they said.
While immediate elimination of the MOPR “would likely better serve ISO-NE’s customers than the proposal that has been filed, such a proposal is unfortunately not before us. And at this late hour, nor could the MOPR be immediately eliminated without causing great uncertainty and delay for FCA 17,” wrote Phillips and Clements.
They cautioned “that we believe this proceeding presents unique circumstances, which may not be present in the case of a similar transition mechanism in a different setting.”
Commissioner Mark Christie concurred in approving the filing “due largely to my belief that RTO capacity markets – which are administrative constructs, not true markets — should attempt to accommodate the public policies of the states as long as the impacts, both in costs and reliability, of one or more states’ public policies are not being forced onto other states not sharing those public policies.”
He said that the threat of such impact-shifting to other states in a multi-state RTO was present in PJM’s proposal last year to eliminate its MOPR.
“Here, however, and in distinct contrast to the PJM MOPR proceeding in which Pennsylvania and Ohio expressed strong opposition in a filing in the proceeding, no state in ISO-NE has filed in this record opposing the MOPR’s reform in ISO-NE,” Christie said.
At the same time, he said that while the policy makers of New England “have made their choices and I respect them, I believe that this proposal, even given the transition mechanism, holds the potential for negative effects on the reliability of electric power service in New England and may even cause higher prices for consumers when state officials find it necessary to procure back-up sources of dispatchable power to keep the lights on, as California is now evidently finding it necessary to do.”
Commissioner James Danly dissented from the order, arguing that the filing approved by FERC “ensures that the capacity market in New England will no longer serve any meaningful purpose except to be used as a tool to suppress prices paid to existing generators. Meanwhile, a fleet of new, state-subsidized renewable resources will force any generator that is not receiving a subsidy—potentially including older renewables—into premature retirement or into expensive, out-of-market reliability must-run contracts (RMR).”
He said he was dissenting “because a market rate design cannot be just and reasonable if it is not competitive, and it cannot be competitive when it permits states to freely manipulate prices. The proposed rate does exactly that and is therefore manifestly unjust and unreasonable.”
APPA Moves To Help Member Utilities Respond To Supply Chain Challenges
May 27, 2022
by Paul Ciampoli
APPA News Director
May 27, 2022
The American Public Power Association (APPA) is taking a number of actions to help its member utilities respond to ongoing supply chain challenges in the electric utility sector.
[This is the final part of a three-part Public Power Current series detailing public power’s response to supply challenges].
Groups Send Letter To Energy Secretary
On May 26, APPA was joined by the National Rural Electric Cooperative Association (NRECA) in sending a letter to Energy Secretary Jennifer Granholm in which the groups urged her “to exercise your authority to immediately address a serious supply chain issue facing our members which could result in electric reliability impacts for Americans as we head into the volatile summer weather months and storm season.”
The letter was signed by Joy Ditto, President and CEO of APPA, and Jim Matheson, CEO of NRECA.
“For months, we have been calling attention to the unprecedented challenges our members are facing in procuring basic equipment needed to restore service following storms and natural disasters,” Ditto and Matheson wrote.
“Transformers pose a particularly acute problem as our members are now facing lead times of more than a year for delivery and in many cases, are being limited in the number they are allowed to purchase. In addition, transformers are critical not only to restoring service but also to extending new service to support economic growth in American communities,” Ditto and Matheson said.
“Therefore, we urge you to temporarily waive the energy conservation standard for distribution transformers to make it possible for manufacturers to increase output as much as possible until this immediate crisis has abated. By relieving manufacturers of the current requirement, raw steel materials used to make distribution transformers can be spread further and result in higher production that our members need. This is a concrete step you can take today to increase transformer availability and address a potential electric reliability issue,” the letter said.
Ditto and Matheson said that they are concerned that if this issue is not addressed quickly, “we could face instances during this upcoming storm season when timely restoration of electric service for some customers simply won’t be possible because of a lack of transformers. As such, we urge you to act without undue delay to increase output for transformers by waiving the energy conservation standard for distribution transformers.”
APPA Develops Web Service To Facilitate Voluntary Transformer Exchange
Meanwhile, in a recent note sent to APPA members, Ditto said that APPA has developed a simple web service to facilitate voluntary transformer exchange and a policy position brief for members looking to have increased conversations in their communities.
She noted that APPA sees supply chain availability as a reliability concern, so it has decided to utilize APPA’s eReliability Tracker (eRT) web-application to address the immediate member need for information related to voluntary transformer sharing.
As a result, APPA members will be able to contact other utilities with similar voltages to discuss equipment if they have an emergency need.
Equipment sharing will be 100% voluntary, with the goal being to have a process for public power utilities to reach out to each other quickly and efficiently and for APPA to help with other parts of the sector (investor-owned utilities and cooperatives) more quickly when there is a need public power utilities can’t meet among themselves.
If a member utility is already subscribed to the eReliability Tracker service, it will be able to fill out the form when logging in using existing credentials. If a utility is not subscribed to the eReliability Tracker APPA is making the voltage based outreach component of the service free through the end of the year, and if you would like to use the request system, contact APPA Staff at Reliability@PublicPower.org.
New APPA Supply Chain Issue Brief
APPA’s recently finalized new supply chain issue brief notes for public power utilities, the ability to provide reliable and affordable power to homes, businesses, and critical facilities is foundational to both their business model and the recovery and expansion of the U.S. economy.
APPA members can download the issue brief here.
APPA Holds Supply Chain Summit
In May, APPA convened a supply chain summit that included participation from public power utility officials who discussed their supply chain challenges and mitigation strategies.
For additional details on the summit and what speakers had to say, read the first part of this three-part series on public power and supply chain challenges.
Click here for the second part of the series.
ISO New England Sees Electrification Driving Demand By 14% Over The Next 10 Years
May 25, 2022
by Peter Maloney
APPA News
May 25, 2022
Electrification is projected to increase annual net electricity use in ISO New England by 14 percent over the next decade, according to a report by the ISO.
The report, 2022-2031 Forecast Report of Capacity, Energy, Loads, and Transmission (CELT), looks at the long-term forecast for energy consumption and peak demand, including 10-year forecasts accounting for the impacts of energy efficiency and behind-the-meter solar generation, as well as capacity with supply obligations and total generating capability. The report also breaks down the region’s generating plants by fuel type.
The ISO develops a gross long-term forecast for electricity demand using state and regional economic forecasts, years of New England weather history, and forecasts for energy demand to power electric vehicles (EVs) and air-source heat pumps. The results of the ISO’s energy efficiency and behind-the-meter solar power forecasts are deducted from the gross forecast to arrive at a net demand forecast.
The report projects gross electric demand of 164,965 gigawatt hours (GWh) in 2031 compared with 140,536 GWh in 2022, and net demand of 140,805 in 2031. Electric vehicles are expected to account for 5,934 GWh of demand in 2031, while air-source heat pumps are expected to account for 3,056 GWh of demand that year. The ISO forecasts energy efficiency will reduce demand by 16,468 GWh in 2031 and behind-the-meter solar installations will reduce demand by 7,692 GWh by 2031.
Assuming average weather conditions, the report projects peak summer demand at 29,519 megawatts (MW) gross and 25,322 MW net in 2031, compared with 27,743 MW and 24,686 MW gross and net, respectively, in 2022.
If weather is hotter than usual, the report estimates peak summer demand of 31,336 MW gross and 27,139 MW net by 2031, compared with 29,472 MW gross and 26,416 MW net in 2022.
Under average weather condition, the ISO forecasts peak winter demand at 25,880 MW gross and 22,852 net in 2031, compared with 22,031 MW gross and 20,009 MW net in 2022.
Under average weather condition, the ISO forecasts peak winter demand at 25,880 MW gross and 22,852 net in 2031, compared with 22,031 MW gross and 20,009 MW net in 2022.
If weather is colder than average, the ISO estimates gross winter demand of 26,725 MW and net demand of 23,696 MW in 2031, compared with 22,717 MW gross and 20,695 MW net in 2022.
The demand forecast report is the primary source for assumptions used in the ISO’s system planning and reliability studies.
PJM Says $3 Billion Needed To Prepare Its Grid For Renewables Influx
May 24, 2022
by Peter Maloney
APPA News
May 24, 2022
As much as $3 billion will needed to be invested in grid enhancements to accommodate a growing amount in renewable resources expected in the PJM Interconnection region, according to a new report by the regional transmission organization.
The Grid of the Future: PJM’s Regional Planning Perspective report aims to ensure that PJM’s grid maintains the reliability and operational flexibility needed to address key drivers that are changing the face of the industry.
Over the next 15 years, PJM anticipates more than 100,000 megawatts (MW) of onshore wind, offshore wind, solar power and energy storage resources will come online in the PJM region, which already has 15,000 MW of renewable resources in service.
“The grid of the future is happening now, and this paper details the road map that will help us plan the transmission system to enable the shift to renewable generation resources that are smaller, more dispersed, and more variable in output than the existing fleet,” Suzanne Glatz, director of strategic initiatives and interregional planning at PJM, said in a statement.
The PJM region includes all or part of 13 states and the District of Columbia.
In the report, PJM planners identified and examined industry trends driving grid expansion, including generation development, evolving load characteristics, emerging transmission technologies and resilience.
The resulting road map for PJM’s Regional Transmission Expansion Plan (RTEP), which identifies transmission system additions and improvements needed to maintain the flow of electricity in the region, encompasses four focus areas.
PJM said it would conduct transmission build-out scenarios studies this year that will build on its renewable integration and offshore wind studies and include further analysis of the potential impacts of greater transportation and building electrification.
PJM said it would continue to conduct targeted reliability studies to explore generation and transmission attributes such as reactive control, stability, system inertia and frequency control, and short-circuit impacts.
PJM said it would also continue to study and implement improvements to its RTEP process. In April, PJM’s planning committee endorsed a proposal aimed at moving generation and other projects through its planning pipeline more quickly to help clear the current backlog.
And PJM said the road map also focuses on regulatory policy impacts that will inform new reliability criteria for such eventualities as extreme events, state electrification policies and Federal Energy Regulatory Commission (FERC) action on regional transmission planning.
In April, FERC directed grid operators to provide information regarding their changing system needs and plans for potential reforms.
President Biden Announces Intent To Renominate FERC Chairman Glick
May 21, 2022
by Paul Ciampoli
APPA News Director
May 21, 2022
President Biden on May 20 announced his intent to renominate Chairman Richard Glick as a member and Chairman of the Federal Energy Regulatory Commission (FERC).
Glick, a Democrat, joined FERC as a commissioner in November 2017, having been appointed by President Trump. He was elevated to Chairman by President Biden in January 2021.
Glick’s current term expires June 30, 2022, although he could continue to serve through the end of the year.
Glick’s renomination would require confirmation by the Senate.